Method of hydraulic fracturing to reduce unwanted water productions

ABSTRACT

A method of hydraulically fracturing a hydrocarbon-bearing subterranean formation ensures that the conductivity of water inflow below the productive zone of the subterranean formation is reduced. The method consists of two principal steps. In the first step, a fracture in and below the productive zone of the formation is initiated by introducing into the subterranean formation a fluid, free of a proppant, such as salt water, fresh water, brine, liquid hydrocarbon, and/or nitrogen or other gases. The proppant-free fluid may further be weighted. In the second step, a proppant laden slurry is introduced into the subterranean formation which contains a relatively lightweight density proppant. Either the fluid density of the proppant-free fluid is greater than the fluid density of the proppant laden slurry or the viscosity of the proppant-free fluid is greater than the viscosity of the proppant laden slurry. The method limits undesirable fracture height growth in the hydrocarbon-bearing subterranean formation during the fracturing.

SPECIFICATION

This application is a continuation of U.S. patent application Ser. No.10/863,731, filed Jun. 9, 2004, which claims the benefit of U.S. patentapplication Ser. No. 60/480,063, filed Jun. 20, 2003.

FIELD OF THE INVENTION

This invention relates to a method of treating subterranean formationsand, more specifically, to hydraulic fracturing treatments forsubterranean formations. Use of the method of the invention reducesunwanted water production which ordinarily may result during hydraulicfracturing.

BACKGROUND OF THE INVENTION

In the production of fluids from subterranean formations, it has been along-standing practice to hydraulically fracture the formation from awellbore to enhance the flow of fluids from the formation into thewellbore. Hydraulic fracturing is typically employed to stimulate wellswhich produce from low permeability formations.

During hydraulic fracturing, a fracturing fluid is injected into thewellbore at high pressures to create fractures in the rock formationsurrounding the bore. The fractures radiate outwardly from the wellbore,typically from a few to hundreds of meters, and extend the surface areafrom which oil or gas drains into the well.

In the absence of suitable boundaries, it is not uncommon duringhydraulic fracturing for the fracture to grow out of the zone ofproductive interest and proceed into a zone of non-productive interest,including zones containing water. Most often, such problem areas areassociated with non-productive fracture growth below the zone ofproductive interest. Many different approaches have been used tominimize or avoid the occurrence of such phenomena including thedevelopment of modified perforating schemes and reduction in treatmentrates. Another approach has been to use a fracturing fluid which carriesa heavy proppant, such as sand. Such methods do not however provide asatisfactory solution to the production of unwanted water.

The problem of undesirable fracture height growth may particularly be aproblem when practicing slickwater treatments, in light of the poortransport properties of slickwater fluids which allow proppants tosettle, forming a “proppant bank” at the bottom of the created fracture.Unfortunately, such proppant banks in contact with water producing zonesoften provide a high permeability conduit for unwanted water production.A need exists to mitigate such occurrences.

SUMMARY OF THE INVENTION

The invention relates to a method of hydraulically fracturing ahydrocarbon-bearing subterranean formation. The conductivity of waterinflow below the productive zone of the subterranean formation isreduced through the method of the invention.

The method consists of two critical steps. In the first step, aproppant-free fluid is introduced into the subterranean formation for atime and at an injection rate sufficient to initiate a fracture in andbelow the productive zone of the formation. In a preferred mode, theproppant-free fluid may comprise salt water, fresh water, brine, liquidhydrocarbon, and/or nitrogen or other gases. The proppant-free fluid mayfurther be weighted. In the second step, a proppant laden slurry isintroduced into the subterranean formation. The proppant laden slurrypreferably contains a relatively lightweight density proppant.Typically, either the fluid density of the proppant-free fluid isgreater than the fluid density of the proppant laden slurry; or theviscosity of the proppant-free fluid is greater than the viscosity ofthe proppant laden slurry.

Where the fluid density of the proppant-free fluid is greater than thefluid density of the proppant laden slurry, the method of the inventionfurther limits undesirable fracture height growth in thehydrocarbon-bearing subterranean formation during the fracturing. Thefracture, initiated by the introduction of the proppant-free fluid,grows below the productive zone of the formation, the proppant-freeslurry migrating to the lower extremities of the initiated fracture bygravity segregation. The density differential of the proppant-free fluidand the proppant laden slurry allows the proppant laden slurry tooverride the dense proppant-free fluid, thereby causing a separation ofthe proppant laden slurry from the proppant-free fluid.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to more fully understand the drawings referred to in theDetailed Description of the Preferred Embodiments, a brief descriptionof the drawings is presented, in which:

FIGS. 1 and 2 are 2D depictions of a fracture, after closure of thefracture, initiated with a fracturing fluid containing sand as theproppant and a brine slickwater fluid.

FIG. 3 is a depiction of a fracture, after closure of the fracture,initiated with a pre-pad fluid, followed by a slickwater brinecontaining an ultra lightweight proppant.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

In the first step of the method of the invention, a fluid is injectedinto the subterranean formation which is void of a proppant. Theinjection of this fluid, often referred to as a “pre-pad,” serves toopen the main body of the fracture and develops a relatively largeradius of curvature near the wellbore. The pre-pad has physicalproperties which lead the subsequently pumped proppant laden slurry oflower density and/or viscosity to override and stay substantiallyseparated from it. Thus, the proppant avoids migration into the lowernon-productive zone of the formation.

The injection rate is typically between from about 5 to about 150barrels per minute. Typically, the volume of pre-pad is determined bythe constraints of the fracture design and may range from 20 to manyhundreds of barrels.

The proppant-free fluid is typically injected into the subterraneanformation at ambient surface temperature and at pressures typically lessthan 10,000 psi. It also being understood that core and/or layermaterials may be selected by those of skill in the art to meet andwithstand anticipated downhole conditions of a given application.

The proppant-free fluid typically may be salt water, fresh water, brine,liquid hydrocarbon and/or nitrogen or other gases or any other pre-padpumping solution known to those of skill in the art. For instance, theproppant-free fluid may be a linear or crosslinked fluid such as apolymeric dispersion of hydrophilic water swellable particlescrosslinked so that they are water insoluble, but capable of swelling inthe presence of relatively small amounts of water. Such polymericparticulates swell and reduce fluid loss to the formation during thetreatment.

In a preferred embodiment, the proppant-free fluid contains a watercontrol additive and/or a relative permeability modifier. Suitable asfluid loss additives include corn starch (especially 100 mesh cornstarch) as well as surfactants comprising an alkyl sarcosinate havingfrom about 12 to 24 carbon atoms in the alkyl group; the latterdisclosed in U.S. Pat. No. 6,491,099, herein incorporated by reference.Particularly preferred as water control additive is AquaCon, a productof BJ Services Company. See U.S. Pat. No. 6,228,812. Incorporation ofsuch water control additives serves to impede the flow of water throughthe created but unpropped fracture below the productive zone. Whenpresent, the total volume of fluid loss additive(s) in the proppant-freefluid is between from about 0.1 to about 5, preferably about 2, volumepercent.

The relative permeability modifier (RPM) for use in the invention is anysubstance known in the art that can impede the production of water.Suitable as the RPM are homopolymers and copolymers of acrylamide,optionally having been sulfonated or quaternized, polyvinylalcohol,polysiloxane, or a hydrophilic polymer selected from natural gums andchemically modified derivatives thereof. Such RPMs include thosedisclosed in U.S. Pat. Nos. 6,228,812, 5,735,349; 6,169,058, and U.S.patent application Ser. No. 10/386,160, filed on Mar. 10, 2003, all ofwhich are herein incorporated by reference.

Most often the RPM is hydrophilic having the ability to remain hydratedin the formation waters and simultaneously having an affinity to adsorbonto the solid formation material. Such RPMs typically have weightaverage molecular weights ranging from about 20,000 to about 20,000,000g/mole, preferably from about 100,000 to about 5,000,000 g/mole, mostpreferably from about 250,000 to about 2,000,000 g/mole.

Further, the term RPM as used herein shall further refer to those RPMsystems as disclosed in U.S. patent application Ser. No. 10/386,160,filed on Mar. 10, 2003, herein incorporated by reference. In addition tothe molecular weight, the RPMs must also have specific sites that allowinteraction with the organosilicon compound. Such RPM systems comprise aRPM (as defined above) and an organosilicon compound In a preferredmode, the organosilicon compound is of the formula:

wherein R is a halogen, hydrogen, or an amine radical which can besubstituted with hydrogen, organic radicals, or silyl groups, R₁ ishydrogen, an amine, or an organic radical having from 1 to 50 carbonatoms, and R₂ and R₃ are hydrogen or the same or different halogens,alkyl, alkenyl, aryl or amines having 1 to 50 carbon atoms; or

-   -   wherein R₄, R₅ and R₆ are independently selected from hydrogen,        amine, halogen, alkoxide, and organic radicals having from 1 to        50 carbon atoms, provided not all of R₄, R₅ and R₆ are hydrogen,        and R₇ is an organic radical having from 1 to 50 carbon atoms,        preferably R₇ is selected from amine, alkyl, alkenyl, and aryl        groups having from 1 to 18 carbon atoms.

In addition to the hydrophillic swelling polymers, the proppant-freefluid may contain a hydrophilic polymer further include natural gumssuch as guar, carrageenan, gum Arabic, gum ghatti, karaya, tragacanth,pectin, starch, locust bean gum, scleroglucan, tamarind and xanthan gumsand any chemically modified derivatives of these gums includingderivatives of cellulose such as the pendent derivatives hydroxyethyl,hydroxypropyl, hydroxypropylcarboxymethyl, hydroxyethylcarboxymethyl,carboxymethyl or methyl or a derivative thereof.

Further, the proppant-free fluid may contain a weighting material inorder to impart higher density to the fluid. Suitable weightingmaterials are those which have one or more water soluble calcium salts(typically calcium halide salts such as CaCl₂, etc.) dissolved therein.Where the proppant-free fluid is a brine, the density of the weightedbrine will generally be in the range of from about 10 to about 18lb/gal, preferably from about 15 to about 18 lb/gal. The high densityproppant-free fluids can suitably also contain other weighting materialsknown in the art such as other water soluble salts like sodium salts,such as sodium chloride, sodium bromide, etc.; zinc salts, such as zincchloride, zinc bromide, etc.; and sodium, potassium and cesium salts offormates and the like. However, in those instances wherein zinc saltssuch as zinc chloride or bromide are to be included, it is generallyadvisable and preferable to limit the amount thereof to a maximum levelof about 2 weight percent or less (based upon the total weight of thebrine composition) in order to minimize the risks of zinc sulfideprecipitation which may otherwise occur within the formation inconnection therewith. Other suitable weighting materials include groundglass, glass powder, as well as fiberglass.

The pre-pad pumping treatment is followed by an injection of aproppant-laden slurry. The propping agents are normally used inconcentrations between about 1 to 18 pounds per gallon of fracturingfluid composition, but higher or lower concentrations can be used asrequired. Typically, from about 2,000 to about 4,000 barrels of proppantladen slurry containing a total of about 100,000 to about 350,000 poundsof proppant is pumped into the formation. The proppant-laden slurry maybe pumped into the formation in successive stages, if desired.

Typically, the proppant-laden slurry is injected into the formation atambient surface temperature and at pressures usually less than 10,000psi. However, these stated conditions are exemplary only.

The proppant-laden slurry is pumped at a rate sufficient to place theproppant into the fracture and form a proppant bank. During the actualpumping the pH may be adjusted by the addition of a buffer, followed bythe addition of the enzyme breaker, crosslinking agent, and otheradditives if required. After deposition, the proppant material serves tohold the fracture open. For reasons apparent below, the proppant-ladenslurry typically does not contain a weighting agent.

In the practice of the invention, proppant-laden slurry may be anycarrier fluid suitable for transporting a mixture of proppant into aformation fracture in a subterranean well. Such fluids include, but arenot limited to, carrier fluids comprising salt water, fresh water,liquid hydrocarbons, and/or nitrogen or other gases. Typically, viscousgels or foams are employed as the fracturing fluid in order to provide amedium that will adequately suspend and transport the solid proppant, aswell as to impair loss of fracture fluid to the formation duringtreatment (commonly referred to as “filterability” or “fluid loss”). Assuch, viscosity of the fracturing fluid may affect fracture geometrybecause fluid loss affects the efficiency of a treatment. For example,when the rate of fluid loss to the formation equals or exceeds the rateof injection or introduction of fluid into a fracture, the fracturestops growing. Conversely, when the rate of fluid loss is less than theinjection or introduction rate, taken together with other factors, afracture continues to propagate. Excessive fluid loss thus results infractures that are smaller and shorter than desired.

In a preferred mode, the proppant is a relatively lightweight orsubstantially neutrally buoyant particulate materials or a mixturethereof. Such proppants may be chipped, ground, crushed, or otherwiseprocessed to produce particulate material having any particle size orparticle shape suitable for use in the methods disclosed herein.Typically, the particle sizes of the proppants employed in the inventionrange from about 4 mesh to about 100 mesh, alternatively from about 8mesh to about 60 mesh, alternatively from about 12 mesh to about 50mesh, alternatively from about 16 mesh to about 40 mesh, andalternatively about 20 to 40 mesh. In one exemplary case, the proppantmay be ground walnut shells having a particle size of about 12/20 USmesh size in the first proppant stage and 20/40 US mesh size in thesecond proppant stage. Such proppants are less subject to settling andcan be more easily transported to provide greater effective proppedfracture length. Greater effective propped fracture length translates toimproved stimulation efficiency, well productivity and, reservoirdrainage. Another benefit of using such particulate materials is thatthe requirements for the mixing equipment are minimized. For instance,when the carrier fluid is a brine, the only requirements on the mixingequipment is that it be capable of (a) mixing the brine (dissolvingsoluble salts), and (b) homogeneously dispersing in the substantiallyneutrally buoyant particulate material.

By “relatively lightweight” it is meant that the particulate has adensity that is substantially less than a conventional proppantparticulate material employed in hydraulic fracturing operations, e.g.,sand or having a density similar to these materials. Especiallypreferred are those particulates having a density less than or equal to3.25 g/cc. Even more preferred are ultra lightweight particulates havinga density less than or equal to 2.25, more preferably less than or equalto 2.0, even more preferably less than or equal to 1.75, most preferablyless than or equal to 1.25, g/cc. Preferably, such particulates areselected from ceramics, resin coated ceramics, glass microspheres,sintered bauxite, resin-coated sintered bauxite, aluminum pellets,aluminum needles, or nylon pellets or a mixture thereof. In aparticularly preferred embodiment, the particulate is a resin coatedceramic particles or beads or is a synthetic organic particle such asnylon pellets, ceramics (including aluminosilicates such as “CARBOLITE,”“NAPLITE” or “ECONOPROP”).

By “substantially neutrally buoyant”, it is meant that a particulate hasa density sufficiently close to the density of an ungelled or weaklygelled carrier fluid (e.g., ungelled or weakly gelled completion brine,other aqueous-based fluid, or other suitable fluid) to allow pumping andsatisfactory placement of the proppant particulate using the selectedcarrier fluid. For example, urethane resin-coated ground walnut hullshaving a density of from about 1.25 to about 1.35 g/cc may be employedas a substantially neutrally buoyant proppant particulate in completionbrine having a density of about 1.2 g/cc. It will be understood thatthese values are exemplary only. As used herein, a “weakly gelled”carrier fluid is a carrier fluid having minimum sufficient polymer,viscosifier or friction reducer to achieve friction reduction whenpumped down hole (e.g., when pumped down tubing, work string, casing,coiled tubing, drill pipe, etc.), and/or may be characterized as havinga polymer or viscosifier concentration of from greater than about 0pounds of polymer per thousand gallons of base fluid to about 10 poundsof polymer per thousand gallons of base fluid, and/or as having aviscosity of from about 1 to about 10 centipoises. An ungelled carrierfluid may be characterized as containing about 0 pounds per thousandgallons of polymer per thousand gallons of base fluid.

Such materials are disclosed in U.S. Pat. Nos. 6,364,018, 6,330,916 and6,059,034, all of which are herein incorporated by reference, and areexemplified by ground or crushed shells of nuts (pecan, almond, ivorynut, brazil nut, macadamia nut, etc); ground or crushed seed shells(including fruit pits) of seeds of fruits such as plum, peach, cherry,apricot, etc.; ground or crushed seed shells of other plants such asmaize (e.g. corn cobs or corn kernels), etc.; processed wood materialssuch as those derived from woods such as oak, hickory, walnut, poplar,mahogany, etc. including such woods that have been processed bygrinding, chipping, or other form of particalization. Preferred areground or crushed walnut shell materials coated with a resin tosubstantially protect and water proof the shell. Such materials may havea density of from about 1.25 to about 1.35 g/cc, and a bulk density ofabout 0.67.

Further, the relatively lightweight particulate for use in the inventionmay be a selectively configured porous particulate, as set forth,illustrated and defined in U.S. Patent Publication No. 20040040708 A1,published on Mar. 4, 2004, herein incorporated by reference.

Also, the relatively lightweight particulate for use in the inventionmay be a well treating aggregate, as set forth, illustrated and definedin U.S. Patent Application Ser. No. 60/569,067, entitled “UltraLightweight Well Treating Aggregates” by Harold Dean Brannon, Allan RayRickards and Christopher John Stephenson, field on May 7, 2004, hereinincorporated by reference.

Those of skill in the art will understand that selection of suitableproppant will depend, in part, on the density of the fluid of theproppant-laden slurry and on whether it is desired that the selectedproppant particle be relatively lightweight or substantially neutrallybuoyant in the selected fluid, and/or whether or not it is desired thatthe fluid be non-gelled or non-viscosified.

The initial proppant-free fluid, as well as the proppant-laden slurry,may also contain other conventional additives common to the well serviceindustry such as breakers, surfactants, biocides, gelling agents,hardening agents, solvents, foaming agents, demulsifiers, buffers, claystabilizers, acids, or mixtures thereof.

In light of the differences in the fluid properties between theproppant-free fluid and the proppant-laden slurry, the proppant-ladenslurry overrides the heavier proppant-free fluid, which has migrateddown into the fracture growth created below the productive zone. Assuch, the conductivity of water inflow below the productive zone of theformation is reduced. Once pumping is completed and the fracture closes,the areas below the productive zone remain un-propped and thus have amuch lower conductivity to inflow of bottom water.

The method of the invention has particular applicability in limitingundesirable fracture height growth in the hydrocarbon-bearingsubterranean formation. Since the fracture, initiated by theintroduction of the proppant-free fluid, grows below the productive zoneof the formation, the proppant-free slurry migrates to the lowerextremities of the initiated fracture. Such growth proceeds by gravitysegregation. The density differential of the proppant-free fluid and theproppant laden slurry allows the proppant laden slurry to override thedense proppant-free fluid, thereby causing a separation of the proppantladen slurry from the proppant-free fluid. After the fracture is closed,the area below the fracture of the productive zone is unpropped. As aresult, the conductivity of inflow of water below the productive zone ofa subterranean formation is reduced.

The following examples will illustrate the practice of the presentinvention in its preferred embodiments. Other embodiments within thescope of the claims herein will be apparent to one skilled in the artfrom consideration of the specification and practice of the invention asdisclosed herein. It is intended that the specification, together withthe examples, be considered exemplary only, with the scope and spirit ofthe invention being indicated by the claims that follow.

EXAMPLES

The Examples demonstrate the ability of the process of the invention tocontrol water production.

A fracture was simulated using the Mfrac three-dimensional hydraulicfracturing simulator of Meyer & Associates, Inc. using a simple 3-layerisotropic homogeneous 0.1 mD permeability gas reservoir model, 40 acrespacing. The fracture was designed to be placed into the zone at atheoretical depth of approximately 9800 to about 9900 feet and the modelwas run in full 3-D mode. Since the Mfrac model does not makecalculations for a partial monolayer, the conductivity of the proppantwas artificially increased at a concentration of 0.5 lbs/sq. ft. at arate of 50 barrels per minute (bpm).

Fracture conductivity between the proppant-packed fracture and that ofthe native reservoir, mathematically defined as:(proppant pack permeability×fracture width)/(formationpermeability×propped fracture half length),is illustrated in the conductivity profiles of FIGS. 1, 2 and 3 afterclosure of the fracture. FIG. 1 is a 2D depiction of the fracture ofinjection of the fracturing fluid using sand as the proppant and astandard 8.4 ppg brine slickwater fluid. FIG. 2 displays an identicaljob design except that a 10 ppg densified slickwater brine was used inplace of the 8.4 ppg brine as fracturing fluid. FIG. 3 displays the samejob design but use of a pre-pad fluid of 10 ppg slickwater brine and theremaining fluid being 8.4 ppg slickwater brine containing LiteProp™ 125lightweight proppant, a product of BJ Services Company, having a densityof 1.25 g/cc. The amount of LiteProp™ 125 is volumetrically equivalentto the jobs set forth in FIG. 1 and FIG. 2. In all three of the fracturedesigns, an identical pump schedule was used in terms of fluid volumes;the proppant mass was adjusted for density differences to yieldequivalent proppant volumes for each job design.

The left hand portion of the figures shows a simulated stress profilethat could be prevalent in cases where a water-bearing lower zone mightbe present. The upper zone 10 on the stress profile is a shale zone witha confining stress that will tend to contain the fracture from growingup too high. The lower zone, 20, on the other hand, has a lower stressprofile that invites the fracture to propagate into it.

The created fracture area, represented as 30, is the area of thereservoir traversed by the brine slickwater fluid. The propped fracturearea, 40, is contributory to well stimulation, and represents the areaof the reservoir propped open to provide improved fracture conductivity.The created but unpropped area 50, heals upon fracture closure and,thus, is not considered to be stimulated.

As evidenced in FIG. 1, the sand proppant settles in lower zone 20,thereby stimulating the water producing zone while providing little, ifany, benefit to the productivity of the zone of interest 60. Theultimate result of the fracture is very high water production, andlittle or no hydrocarbon production. Little difference between thesimulations of FIG. 1 and FIG. 2 can be detected. The additional brinedensity modifies proppant transport somewhat, but overall the resultsare very similar. As set forth in FIG. 3, the densified 10 ppgslickwater brine migrates toward the bottom of the fracture, allowingthe ultra lightweight density (8.4 ppg slickwater) brine to override thehigher density brine and stay mostly in zone of interest 60. Thisprocess effectively limits, if not eliminates, water production from anadjacent water zone below the zone of interest and shows no increase inconductivity in the water producing zone.

Other embodiments within the scope of the claims herein will be apparentto one skilled in the art from consideration of the specification andpractice of the invention as disclosed herein. It is intended that thespecification be considered exemplary only, with the scope and spirit ofthe invention being indicated by the claims which follow.

1. A method of hydraulically fracturing a hydrocarbon-bearingsubterranean formation which comprises: (a) introducing a proppant-freefluid into the subterranean formation for a time and at an injectionrate sufficient to initiate fracturing; (b) introducing into thesubterranean formation a proppant laden slurry containing relativelylightweight density proppant; wherein at least one of the followingconditions prevail: (i.) the fluid density of the proppant-free fluid isgreater than the fluid density of the proppant laden slurry; or (ii) theviscosity of the proppant-free fluid is greater than the viscosity ofthe proppant laden slurry.
 2. The method of claim 1, wherein the densityof the relatively lightweight density proppant is less than or equal to3.25 g/cc.
 3. The method of claim 2, wherein the relatively lightdensity proppant is an ultra lightweight density proppant having adensity less than or equal to 2.25 g/cc.
 4. The method of claim 3,wherein the density of the ultra lightweight density proppant is lessthan or equal to 1.75 g/cc.
 5. The method of claim 4, wherein thedensity of the ultra lightweight density proppant is less than or equalto 1.25 g/cc.
 6. The method of claim 1, wherein the relativelylightweight density proppant is selected from ceramics, resin coatedceramics, glass microspheres, sintered bauxite, resin-coated sinteredbauxite, aluminum pellets, aluminum needles, nylon pellets, ground orcrushed shells of nuts, seed shells crushed fruit pits, or processedwood materials or a mixture thereof.
 7. The method of claim 1, whereinthe relatively lightweight density proppant is a selectively configuredporous particulate or a well treating aggregate.
 8. The method of claim1, wherein the fracture in the subterranean formation is initiated by afluid which contains a breaker, surfactant, biocide, gelling agent,curable resin, hardening agent, solvent, foaming agent, demulsifier,buffer, clay stabilizer, acid, or a mixture thereof.
 9. The method ofclaim 1, wherein the fracture in the subterranean formation is initiatedby a fluid which comprises salt water, fresh water, liquid hydrocarbon,and/or nitrogen or other gases.
 10. The method of claim 1, wherein thefluid introduced to the formation in step (a) is weighted.
 11. Themethod of claim 10, wherein the weighted fluid introduced to theformation in step (a) further comprises a water control additive. 12.The method of claim 10, wherein the weighted fluid introduced to theformation in step (a) further comprises a relative permeabilitymodifier.
 13. A method of limiting undesirable fracture height growth ina hydrocarbon-bearing subterranean formation during hydraulicfracturing, the method comprising: (a) initiating a hydraulic fracturethat grows below the productive zone of the formation by pumping a denseliquid into the formation for a time sufficient for the liquid tomigrate to the lower extremities of the initiated fracture by gravitysegregation (b) introducing into the formation a proppant laden slurrycontaining a relatively lightweight density proppant, the density and/orviscosity of the relatively lightweight density proppant being less thanthe density and/or viscosity of the liquid of step (a); and (c) allowingthe proppant slurry to override (by density differential) the liquidpumped into the formation in step (a) for a time sufficient so as toseparate the proppant slurry from the liquid pumped into the formationin step (a).
 14. The method of claim 13, wherein the density of therelatively lightweight density proppant is less than or equal to 3.25g/cc.
 15. The method of claim 14, wherein the relatively lightweightdensity proppant is an ultra lightweight density proppant having adensity less than or equal to 2.25 g/cc.
 16. The method of claim 15,wherein the density of the ultra lightweight density proppant is lessthan or equal to 1.75 g/cc.
 17. The method of claim 16, wherein thedensity of the ultra lightweight density proppant is less than or equalto 1.25 g/cc.
 18. The method of claim 13, wherein the relativelylightweight density proppant is selected from ceramics, resin coatedceramics, glass microspheres, sintered bauxite, resin-coated sinteredbauxite, aluminum pellets, aluminum needles, nylon pellets, ground orcrushed shells of nuts, seed shells crushed fruit pits or processed woodmaterials or a mixture thereof.
 19. The method of claim 13, wherein therelatively lightweight density proppant is a selectively configuredporous particulate or a well treating aggregate.
 20. The method of claim13, wherein the fracture in the subterranean formation is initiated by afluid which contains a breaker, surfactant, biocide, gelling agent,curable resin, hardening agent, solvent, foaming agent, demulsifier,buffer, clay stabilizer, acid, or a mixture thereof. 21-33. (canceled)